Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms a reservoir in which hydrocarbons are able to collect. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As the drilling progresses downward, the drill string is extended by adding more pipe sections.
When the drill bit has reached the desired depth, larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. Cement is introduced through a work string. As it flows out the bottom of the work string, fluids already in the well, so-called “returns,” are displaced up the annulus between the casing and the borehole and are collected at the surface.
Once the casing is cemented in place, it is perforated at the level of the oil bearing formation to create openings through which oil can enter the cased well. Production tubing, valves, and other equipment are installed in the well so that the hydrocarbons may flow in a controlled manner from the formation, into the cased well bore, and through the production tubing up to the surface for storage or transport.
This simplified drilling and completion process, however, is rarely possible in the real world. Hydrocarbon bearing formations may be quite deep or otherwise difficult to access. Thus, many wells today are drilled in stages. An initial section is drilled, cased, and cemented. Drilling then proceeds with a somewhat smaller well bore which is lined with somewhat smaller casings or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A seal also is typically established between the liner and the casing and, like the original casing, the liner is cemented in the well. That process then may be repeated to further extend the well and install additional liners. In essence, then, a modern oil well typically includes a number of tubes wholly or partially within other tubes.
Moreover, hydrocarbons are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons are able to flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations. In particular, various techniques are available for increasing production from formations which are relatively nonporous.
One technique involves drilling a well in a more or less horizontal direction, so that the borehole extends along a formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Another technique involves creating fractures in a formation which will allow hydrocarbons to flow more easily. Indeed, the combination of horizontal drilling and fracturing, or “frac'ing” or “fracking” as it is known in the industry, is presently the only commercially viable way of producing natural gas from the vast majority of North American gas reserves.
Fracturing typically involves installing a production liner in the portion of the well bore which passes through the hydrocarbon bearing formation. In shallow wells, the production liner may actually be the casing suspended from the well surface. In either event, the production liner is provided, by various methods discussed below, with openings at predetermined locations along its length. Fluid, most commonly water, then is pumped into the well and forced into the formation at high pressure and flow rates, causing the formation to fracture and creating flow paths to the well. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the frac fluid and are carried into the fractures. The proppant serves to prevent fractures from closing when pumping is stopped.
A formation usually is fractured at various locations, and rarely, if ever, is fractured all at once. Especially in a typical horizontal well, the formation usually is fractured at a number of different points along the bore in a series of operations or stages. For example, an initial stage may fracture the formation near the bottom of a well. The frac job then would be completed by conducting additional fracturing stages in succession up the well.
Some operators prefer to perform a frac job on an “open hole,” that is without cementing the production liner in the well bore. The production liner is provided with a series of packers and is run into an open well bore. The packers then are installed to provide seals between the production liner and the sides of the well bore. The packers 2i are spaced along the production liner at appropriate distances to isolate the various frac zones from each other. The zones then may be fractured in a predetermined sequence. The packers in theory prevent fluid introduced through the liner in a particular zone from flowing up or down the well bore to fracture the formation in areas outside the intended zone.
Certain problems arise, however, when an open hole is fractured. The distance between packers may be substantial, and the formation is exposed to fluid pressure along that entire distance. Thus, there is less control over the location at which fracturing of a formation will occur. It will occur at the weakest point in the frac zone, i.e., the portion of the well bore between adjacent packers. Greater control may be obtained by increasing the number of packers and diminishing their separation, but that increases the time required to complete the frac job. Moreover, even if packers are tightly spaced, given the extreme pressures required to fracture some formations and the rough and sometimes frangible surface of a well bore, it may be difficult to achieve an effective seal with a packer. Thus, fluid may flow across a packer and fracture a formation in areas outside the intended zone.
In part for such reasons, many operators prefer to cement the production liner in the well bore before the formation is fractured. Cement is circulated into the annulus between the production liner and well bore and is allowed to harden before the frac job is commenced. Thus, frac fluid first penetrates the cement in the immediate vicinity of the inner openings before entering and fracturing the formation. The cement above and below the liner openings serves to isolate other parts of the formation from fluid pressure and flow. Thus, it is possible to control more precisely the location at which a formation is fractured when the production liner is first cemented in the well bore. Cementing the production liner also tends to more reliably isolate a producing formation than does installing packers. Packers seat against a relatively small portion of the well bore, and even if an effective seal is established initially, packers may deteriorate as time passes.
There are various methods by which a production liner is provided with the openings through which frac fluids enter a formation. In a “plug and perf” frac job, the production liner is made up from standard lengths of casing. The liner does not have any openings through its sidewalls. It is installed in the well bore, either in an open bore using packers or by cementing the liner, and holes then are punched in the liner walls. The perforations typically are created by so-called perforation guns which discharge shaped charges through the liner and, if present, adjacent cement.
The production liner typically is perforated first in a zone near the bottom of the well. Fluids then are pumped into the well to frac the formation in the vicinity of the perforations. After the initial zone is fracked, a plug is installed in the liner at a point above the fractured zone to isolate the lower portion of the liner. The liner then is perforated above the plug in a second zone, and the second zone is fracked. That process is repeated until all zones in the well are fractured.
The plug and perf method is widely practiced, but it has a number of drawbacks. Chief among them is that it can be extremely time consuming. The perf guns and plugs must be run into the well and operated individually, often times at great distance and with some difficulty. After the frac job is complete, it also may be necessary to drill out or otherwise remove the plugs to allow production of hydrocarbons through the liner. Thus, many operators prefer to frac a formation using a series of frac valves.
Such frac valves typically include a cylindrical housing that may be threaded into and forms a part of a production liner. The housing defines a central conduit through which frac fluids and other well fluids may flow. Ports are provided in the housing that may be opened by actuating a sliding sleeve. Once opened, fluids are able to flow through the ports and fracture a formation in the vicinity of the valve.
The sliding sleeves in such valves traditionally have been actuated either by creating hydraulic pressure behind the sleeve or by dropping a ball on a ball seat which is connected to the sleeve. Typical multi-stage fracking systems will incorporate both types of valves. Halliburton's RapidSuite sleeve system and Schlumberger's Falcon series sleeves, for example, utilize a hydraulically actuated “initiator” valve and a series of ball-drop valves.
More particularly, the production liner in those systems is provided with a hydraulically actuated sliding sleeve valve which, when the liner is run into the well, will be located near the bottom of the well bore in the first fracture zone. The production liner also includes a series of ball-drop valves which will be positioned in the various other fracture zones extending uphole from the first zone.
A frac job will be initiated by increasing fluid pressure in the production liner. The increasing pressure will actuate the sleeve in the bottom, hydraulic valve, opening the ports and allowing fluid to flow into the first fracture zone. Once the first zone is fractured, a ball is dropped into the well and allowed to settle on the ball seat of the ball-drop valve immediately uphole of the first zone. The seated ball isolates the lower portion of the production liner and prevents the flow of additional frac fluid into the first zone. Continued pumping will shift the seat downward, along with the sliding sleeve, opening the ports and allowing fluid to flow into the second fracture zone. The process then is repeated with each ball-drop valve uphole from the second zone until all zones in the formation are fractured.
Such systems have been used successfully in any number of well completions. The series of valves avoids the time consuming process of running and setting perf guns and plugs. Instead, a series of balls are dropped into the well to successively open the valves and isolate downhole zones. It may still be necessary, however, to drill out the liner to remove the balls and seats prior to production. Unlike plug and perf jobs, there also is a practical limit to the number of stages or zones that can be fractured.
That is, the seat on each valve must be big enough to allow passage of the balls required to actuate every valve below it. Conversely, the ball used to actuate a particular valve must be smaller than the balls used to actuate every valve above it. Given the size constraints of even the largest diameter production liners, only so many different ball and seat sizes may be accommodated. Halliburton's RapidStage ball-drop valves, for example, only allow for fracking of up to twenty zones. While that capability is not insignificant, operators may prefer to perform an even greater number of stages using a single liner installation.
Thus, various designs have been proposed for “indexing” ball-drop frac valves. That is, ball-drop valves have been designed to allow an initial ball of a given size to pass through a particular valve in a production liner without actuating the sliding sleeve to open the valve ports. It will pass through the valve typically to actuate the sleeve and open the ports in another valve located downhole from the first valve. After one or more balls are allowed to pass, depending on the design, the uphole valve may be actuated by pumping another ball of the same size into the valve. Balls of the same size, therefore, may be used to actuate two or more valves in the production liner.
Examples of such indexing ball-drop frac valves are disclosed in U.S. Pat. App. Publ. 2013/0,025,868 of C. Smith et al. (“Smith '868”), U.S. Pat. App. Publ. 2011/0,278,017 of D. Themig et al. (“Themig '017”), U.S. Pat. App. Publ. 2009/0,308,588 of M. Howell et al. (“Howell '588”), and U.S. Pat. App. Publ. 2011/0,203,800 of D. Tinker et al. (“Tinker '800”). Smith '868, for example, discloses a traveling collet that indexes linearly, that is, that indexes along the main axis running lengthwise through the tool. More specifically, the traveling collet indexes linearly down through the central conduit of the valve as successive balls—all of the same size—are passed through the valve. The collet catches and then releases each of the initial balls, indexing down one unit as each ball passes. When it is fully indexed, the travelling collet engages a sliding sleeve, driving it downward to open the ports.
More specifically, the traveling collet has an upper and a lower set of fingers. Each set of fingers undergo relative expansion and compression as protrusions on the fingers ride in and out of a series of annular recesses spaced out along the central conduit. When the fingers are riding out of a recess, they are compressed and will form a seat that can capture a ball. When they ride into a recess, the fingers relax, and the ball is able to pass through the fingers.
In the run-in position, the upper fingers on the travelling collet are riding out of a recess and are in their compressed state and form a ball seat. The lower fingers are resting in a recess. When a ball is dropped, therefore, it will land on the seat formed by the upper fingers and hydraulic pressure behind the ball will drive the collet downward. As the collet travels downward, the upper fingers will move into a recess, allowing the upper fingers to expand and release the ball. By this time, however, the lower fingers have been driven out of their recess, and now are compressed and form a ball seat. The ball which has just been released by the upper fingers, therefore, will land on the seat formed by the lower fingers and drive the travelling collet further down the main bore. That movement causes the upper fingers to ride out of their recesses—to reform a ball seat—and causes the lower fingers to ride into another, lower recess and release the ball.
The net effect of that catch-release-catch-release is that the first ball will pass through the valve without opening the ports, but will caused the travelling collet to index downward one unit. Successive balls of the same size then may be dropped through the valve until the travelling collet is fully indexed. The next ball that is dropped then will actuate the sleeve and open the ports.
Themig '017 discloses a similar travelling collet with a lower set of fingers (a “catcher”) and an upper set of fingers (a “ball stop”). The travelling collet, however, is not configured to index down multiple units. A first ball will pass through the ball stop and land on the catcher, shifting the collet down. As the collet moves down, the catcher ramps open and releases the ball while the ball stop is compressed. The next ball, therefore, passes through the catcher, lands on the ball stop, and actuates the sleeve to open the ports. Other types of catchers and ball stops are disclosed, such as a shear out actuation ring, radially compressible, resilient C-rings, and elastically deformable seats.
Themig '017 also discloses valves that may be indexed several times. Those valves have a reciprocating driver that rotates within the central conduit and indexes angularly about the tool's main axis as successive balls are passed through the valve. The driver catches and then releases each ball, reciprocating linearly and indexing angularly one unit. When it is fully indexed, the driver catches, but does not release the next ball pumped into the valve, and drives the sleeve to open the ports.
More particularly, the driver in the Themig '017 valve is spring-loaded and is mounted in the central conduit by cooperating pins and a walking-J keyway. The driver has a radially compressible and resilient C-ring that may be compressed to form a ball seat and allowed to expand so as to release a ball. The first ball will land on the compressed C-ring and urge the driver downward until the C-ring expands and releases the ball. After the ball is released, the spring will urge the driver back upward so as to compress the C-ring into a ball seat again. That reciprocating movement will cause the driver to rotate along the keyway and index angularly one unit. Successive balls will cause the driver to reciprocate and rotate angularly additional units until the driver has been fully indexed. At that point, the C-ring will capture, but not release the next ball pumped into the valve, and the keyway allows the driver to move downward into engagement with the sleeve to open the ports.
Howell '588 discloses a reciprocating driver which indexes angularly in a similar fashion. Instead of a compressible C-ring, however, the driver has a set of collet fingers that may be compressed to form a ball seat. The collet fingers first engage and then release successive balls until the driver has been fully indexed. Once the driver has been fully indexed, the next ball will land on the collet fingers, which are now prevented from expanding, and move the driver into engagement with the sleeve to open the ports.
Tinker '800 discloses indexing ball-drop valves, but unlike the valves disclosed in Smith '868, Themig '017, and Howell '588 as discussed above, the valves do not utilize a collet or other type of driver that indexes—either linearly or angularly—and then engages and drives a valve sleeve. Instead of ultimately being actuated by an indexing driver, the sliding sleeve in the Tinker '800 valves indexes down the valve. That is, the valve sleeve is spring loaded. A ball passing through the valve will land on a load pawl and ratchet pawl. As the ball is blown through the pawls, they are deflected and allow the spring to index the sleeve downward one unit. Successive balls will index the sleeve additional units, until the sleeve uncovers the port.
Such designs, at least in theory, offer the promise of being able to selectively actuate a particular valve, and to actuate a series of valves in succession using a single-sized ball. At the same time, however, they suffer various shortcomings. For example, when a ball is pumped down a production liner, especially if the ball is relatively large, it will impact a ball seat with considerable force. Such force may be sufficient to cause a traveling, linearly indexing driver, such as the collets used in the Smith '868 valves, to index more than one unit. If that happens, the valve may be opened too soon and a downstream valve may never be opened. It may be opened with the initial ball, in which case none of the downstream valves will be opened. Alternately, if the valve was not supposed to open until the fourth ball was dropped, for example, it may instead open on the third or second ball pumped through the liner, again leaving one or more downstream valves unopened.
Valves that utilize a rotating, angularly indexing driver, such as the valves disclosed in Themig '017 and Howell '588, are not so susceptible to such problems. The driver must travel back upwards before it can index another unit. Rotating, angularly indexing drivers utilizing pins and keyways, however, are susceptible to jamming, especially when a valve is run into a horizontal well bore. Torque and friction can be created around the driver that may interfere with its operation.
Conventional valves, of both the linearly indexing and angularly indexing designs, also often are poorly suited for incorporation into a liner that will be cemented in place prior to fracturing the formation. Cement passing through the valve conduit when the casing is cemented may hang up in the valve and interfere with subsequent operation of the sleeve or travel of the driver. In addition, many such designs create restrictions through the bore that may undesirably limit the flow of production fluids from the formation to the surface.
It also will be appreciated that indexing valves, like basic ball drop valves, incorporate a seat upon which a ball may land so as to restrict flow of fluids through the valve, thereby allowing fluid flow to be directed out the housing ports once they have been opened. While such isolation seats necessarily must capture a ball after the ports have been opened, they must allow the balls that are used to index the valve before the ports are opened to pass through the valve. In addition, once a ball has landed on the isolation seat and fracturing has been completed, the ball must be released or otherwise removed from the seat so that production is allowed to flow upwards through the valve. The isolation seats also must allow balls to pass back through the valve. Indexing valves, therefore, have incorporated isolation seats that are designed to selectively capture and release a ball.
For example, Weatherford's ZoneSelect i-ball valve, which appears to correspond generally to the valves disclosed in Smith '868, incorporates a spring-loaded collet with fingers that may be compressed to form an isolation ball seat. The fingers on the spring-loaded collet remain in an expanded state as the traveling collet indexes down the tool. The balls used to index the travelling collet, therefore, are allowed to pass through the valve.
When the travelling collet is fully indexed it will drive the sliding sleeve downward to open the ports, which in turn drives the spring-loaded collet downward against resistance from the spring. As it travels downward, the fingers on the spring-loaded collet are compressed into a seat which captures the ball and restricts flow of fluid through the valve. Fluid pumped into the liner, therefore, is forced out the ports to fracture the formation.
Once pumping is stopped, the spring urges the collet upwards toward its original position, allowing the fingers to once again expand. The ball captured by the spring-loaded collet is thereby released. Balls which had passed through the valve to index or isolate downhole valves also are able to flow back up the liner through the valve and, specifically, through the spring-loaded collet.
A problem can arise, however, if pumping is interrupted for any reason after the ports have been opened, but before fracturing of the formation is completed. Any reduction in hydraulic pressure above the valve during such interruptions may allow the spring-loaded collet to travel upward toward its original position and release the ball. Once that happens, the collet is incapable of recapturing the ball so that flow through the valve is shut off. An operator, therefore, will no longer have the ability to selectively fracture the formation adjacent the valve. Any continued pumping will force fluids not only through the ports in the valve, but also through ports in opened valves downhole of the valve.
The ability to selectively inject fluid into various zones in a well bore is important not only in fracturing, but in other processes for stimulating hydrocarbon production. Aqueous acids such as hydrochloric acid may be injected into a formation to clean up the formation. Water or other fluids may be injected into a formation from a “stimulation” well to drive hydrocarbons toward a production well. In many such stimulation processes, as in fracturing a well, the ability to selectively flow fluids out a series of valves may improve the efficacy and efficiency of the process.
Accordingly, there remains a need for new and improved sliding sleeve stimulation valves and for new and improved methods for fracking or otherwise stimulating formations using sliding sleeve valves. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.